20240315PAC to Staff 1-18.pdf

1407 W North Temple, Suite 330
Salt Lake City, Utah 84116

March 15, 2024

Monica Barrios-Sanchez
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd.
Bldg. 8, Ste. 201-A
Boise, ID 83714
[e-mail]
[e-mail]

RE: ID PAC -E-24-01
IPUC Set 1 (1-18)

Please find enclosed Rocky Mountain Power’s Responses to IPUC 1st Set Data Requests 1-18.
Also provided is Attachment IPUC 6. Provided via BOX are Confidential Attachments IPUC 2,
8, 9, and 1 8. Confidential information is provided subject to protection under IDAPA
31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission’s Rules of Procedure No.
67 – Information Exempt from Public Review, and further subject to the non-disclosure
agreement (NDA) executed in this proceeding.

If you have any questions, please feel free to call me at [phone].

Sincerely,

____/s/____
Mark Alder
Manager, Regulation

Enclosures

RECEIVED
Friday, March 15, 2024 2:07PM
IDAHO PUBLIC
UTILITIES COMMISSION
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 1

IPUC Data Request 1

Please explain whether the load forecast used in the proposed load and resource
balance is the Company's latest load forecast. Also, please explain when this load
forecast was created.

Response to IPUC Data Request 1

The load forecast used in the proposed load and resource balance in this
proceeding is the Company’s most recent forecast created May 2023.

Recordholder: Lee Elder

Sponsor: Lee Elder
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 2

IPUC Data Request 2

Please explain why Public Utility Regulatory Policies Act of 1978 (PURPA)
contracts in other states are assumed to expire at the end of their current contracts,
instead of assuming a 79% probability of renewal based on the 2023 IRP.

Response to IPUC Data Request 2

Within the Order issued in Case PAC-E-22-14, specifically Idaho Public Utilities
Commission (IPUC) Order No. 35834 dated June 29, 2023, Issue 5 on page 8
relates to the assumed renewal of Public Utility Regulatory Policies Act of 1978
(PURPA ) projects located in the State of Idaho, while Issue 6 on page 9 relates to
the inclusion of only approved contracts in the load and resources analysis. The
Company interpreted PURPA contract renewal for resources outside of Idaho
based on the IPUC’s direction in Issue 6.

If the 79 percent probability of renewal assumed in PacifiCorp’s 2023 Integrated
Resource Plan (IRP) was kept in place for qualifying facilities (QF) outside the
State of Idaho, it would have no impact until 2027, when it would increase
summer resource capacity by 14 megawatts (MW), and winter resource capacity
by 16 MW. Please refer to Confidential Attachment IPUC 2.

Confidential information is provided subject to protection under IDAPA
31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission’s Rules of
Procedure No. 67 – Information Exempt from Public Review, and further subject
to the non-disclosure agreement (NDA) executed in this proceeding.

Recordholder: Dan MacNeil

Sponsor: Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 3

IPUC Data Request 3

Please confirm that non-PURPA contracts are assumed to expire at the end of
their contract terms in the load and resource balance.

Response to IPUC Data Request 3

In general, non-Public Utility Regulatory Policies Act of 1978 (PURPA ) contracts
are assumed to expire at the end of their contact terms. However, certain
interruptible load contracts are assumed to continue, consistent with the continued
inclusion of the associated loads in the load forecast.

Recordholder: Dan MacNeil

Sponsor: Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 4

IPUC Data Request 4

Please explain whether projected growth is included in the existing Demand
Response (DR) programs and how projected growth is determined. Also, please
explain how this is reflected in the load and resource balance.

Response to IPUC Data Request 4

Projected growth for existing demand response (DR) programs is not included in
the existing DR program category. Growth of existing DR programs is reflected
in the Company’s Conservation Potential Assessment (CPA). Projected growth of
existing DR programs is determined by reviewing historical trends and applying
Northwest Power Planning Council (NW Council) assumptions for growth to each
existing program.

For details on how existing DR programs are reflected in the load and resource
balance, please refer to the confidential work paper accompanying the Company’s
application in this proceeding, specifically confidential file “PAC-E-24-01 RMP
CONF Workpapers 1-19-24”. Existing DR is included as a deduction to the peak
load obligation, included in the totals on rows 16 and 39 of tabs “Smr Peak L&R
(No Proxy, Update)” and “Wtr Peak L&R (No Proxy, Update)”. The planning
reserve margin (PRM) is applied to the load after energy efficiency (EE) and DR
are netted out, so these programs also avoid the PRM requirements that would
otherwise be applicable to the load that they offset. Note: for this application,
consistent with prior orders, both existing and planned and approved DR is
included on the referenced lines. Within the Integrated Resource Plan (IRP)
planned DR (both approved and not yet approved) was designated as “new”. The
Company has modified the labels within column I of tab
“Generator_Battery_Data” – yellow highlight indicates planned and approved DR
that was labeled as “new” within PacifiCorp’s 2023 IRP.

Recordholder: Peter Schaffer / Dan MacNeil

Sponsor: Peter Schaffer / Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 5

IPUC Data Request 5

Please explain how approved future demand response (DR ) programs with their
growth are reflected in the load and resource balance and how the growth
associated with approved future DR programs is determined.

Response to IPUC Data Request 5

Future demand response (DR) programs that have been approved are referred to
as “Planned” resources within the load and resource balance. Similar to existing
DR programs, near term growth is characterized in the Conservation Potential
Assessment (CPA). Near term growth characterized in the CPA for planned DR
programs is calibrated to projections included in the Company’s program
approval filings.

For additional details on the inclusion of planned DR in this application, please
refer to the Company’s response to IPUC Data Request 4.

Recordholder: Peter Schaffer / Dan MacNeil

Sponsor: Peter Schaffer / Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 6

IPUC Data Request 6

Please provide an example to compare demand response (DR) as a resource
versus DR as a load decrement, explain which method is used in the proposed
load and resource balance, and explain whether both will result in the same
capacity position.

Response to IPUC Data Request 6

Please refer to Attachment IPUC 6 which provides the requested example. The
Company’s filing included demand response (DR) as a load decrement. The
Company’s calculation includes a 13 percent planning reserve margin (PRM),
applied to load net of private generation (PG), energy efficiency (EE) and DR. As
a result, moving DR from a load decrement to a resource would result in a 13
percent greater need for resources, to produce an equivalent load and resource
balance.

Recordholder: Dan MacNeil

Sponsor: Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 7

IPUC Data Request 7

Please confirm whether contracts included in the load and resource balance have
sufficient regulatory certainty. Specifically, contracts that require pre-approval
have been approved, and contracts that do not require pre-approval have been
executed and are eligible for recovery.

Response to IPUC Data Request 7

In general, qualifying facilities (QF) in the State of Idaho require approval, as do
large QF in Utah (greater than 3 megawatts (MW)). There were no QF contracts
pending approval by these jurisdictions at the time of the Company’s application
in this proceeding.

Besides the limited exceptions described above, contracts generally take effect
upon execution and do not require commission approvals. The Company is not
aware of any outstanding exceptions at this time. For details on the current
contracts included in the application in this proceeding, please refer to the
confidential work paper accompanying the Company’s filing, specifically
confidential file “PAC-E-24-01 RMP CONF Workpapers 1-19-24”, tab
“Resources as of Dec 31 2023”.

Recordholder: Dan MacNeil

Sponsor: Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 8

IPUC Data Request 8

Page 8 of the Application states that the load and resource balance includes all
contracts executed through December 31, 2023. Please provide contract updates
between then and the time the response is provided to this request. For contract
additions, please only include those with regulatory certainty.

Response to IPUC Data Request 8

Please refer to Confidential Attachment IPUC 8 which provides an updated
version of the load and resource balance that includes recently executed contracts.
Through February 29, 2024, the Company has entered contracts with two small
solar resources in Oregon, neither of which is subject to further commission
approval.

Confidential information is provided subject to protection under IDAPA
31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission’s Rules of
Procedure No. 67 – Information Exempt from Public Review, and further subject
to the non-disclosure agreement (NDA) executed in this proceeding.

Recordholder: Dan MacNeil

Sponsor: Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 9

IPUC Data Request 9

Page 6 of the Application states that Front Office Transactions (FOT) that have
already been contracted are included in the load and resource balance (L&R ). Please
respond to the following.

(a) Please list each FOT's contracting party, delivery amount, and delivery time.

(b) Please confirm that the contracted FOTs are reflected on the line labeled
"Committed Market Purchases with Reserves" in the L&R.

(c) Please explain the rationale behind the sum of "Max Market Purchases Target
with Reserves" and "Committed Market Purchases with Reserves" that represents
the total FOTs.

(d) Please explain why "Committed Market Purchases with Reserves" should not be
subject to the "Max Market Purchases Target with Reserves" FOT limit.

(e) In 2024, the 1,282-MW "Committed Market Purchases with Reserves" is greater
than the 515-MW "Max Market Purchases Target with Reserves" FOT limit.
Please explain whether that shows the FOT limit is not accurate.

(f) Please confirm that determination of "Max Market Purchases Target with
Reserves" FOT limit considers both market availability and transmission
availability. If yes, between these two factors, which one is more limiting to the
Company?

(g) Does the 1,282-MW "Committed Market Purchases with Reserves" have
corresponding transmission availability to allow the transactions? Has the
Company reserved the transmission capacity?

Response to IPUC Data Request 9

(a) Please refer to Confidential Attachment IPUC 9.

(b) Confirmed. The referenced line is 103 percent of the contracted volumes provided
in Confidential Attachment IPUC 9.

(c) The "Max Market Purchases Target with Reserves" is a target, identified in the
Integrated Resource Plan (IRP). Within the IRP, this target represents the level of
market reliance, i.e. a portion of the Company’s portfolio that does not need to be
met with long-term commitments. The Company has purchased more than this
level in the past, but this does not indicate that such purchases will be possible in
the future. Further, in the first few years of the IRP, it may not be possible to
reach the target, due to the time to bring new resources online. Summing the two
referenced values results in the highest possible level of market purchases, though
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 9

it is still not sufficient to eliminate the shortfall in 2024. While “Max Market
Purchases Target with Reserves” may be useful as a reference, it has no bearing
on the Company’s actual operations or procurement of short-term contracts to
meet its load requirements.

(d) In actual operations, the Company has to secure sufficient resources to serve its
customer’s requirements. If long-term resources are not sufficient, short-term
resources will be necessary to make up any difference, regardless of targets set in
the IRP.

(e) Please refer to the Company’s response to subpart (c) above. In PacifiCorp’s 2019
IRP, the target for market purchases was 1,425 megawatts (MW) before adding 3
percent for avoided contingency reserves. Please refer to the 2019 IRP, Volume I,
page 170, Table 6.12 (Maximum Available Front Office Transaction Quantity by
Market Hub) which is publicly available and can be accessed by utilizing the
following website link:

https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/i
ntegrated-resource-plan/2019_IRP_Volume_I.pdf

A lower target for market purchases was identified in the Company’s 2021 IRP
published in September 2021, but long-term procurements generally at least two
to three years after execution, so it will take time to achieve the targeted level.

(f) The "Max Market Purchases Target with Reserves" front office transaction (FOT)
limit accounts for both market availability and transmission availability. The
Company has firm transmission rights in excess of the current limits but is
concerned that no sellers may be available during strained conditions across the
region. To reflect this, market purchase limits vary by location and by season,
with markets tied to California only available in the winter.

(g) The transactions in Confidential Attachment IPUC 9 are all at points where the
Company has existing long-term transmission rights. The Company utilizes all
existing long-term and short-term transmission for serving its obligations and
would purchase additional transmission as needed.

Confidential information is provided subject to protection under IDAPA 31.01.01.067
and 31.01.01.233, the Idaho Public Utilities Commission’s Rules of Procedure No. 67
– Information Exempt from Public Review, and further subject to the non-disclosure
agreement (NDA) executed in this proceeding.

Recordholder: Dan MacNeil / Paul Wood

Sponsor: Dan MacNeil / Paul Wood
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 10

IPUC Data Request 10

Page 8 of the Application states that "[t]he same methodology has been used for
resources included in the 2023 IRP and for resources added after the 2023 IRP."
Please respond to the following.

(a) Please describe the methodology.

(b) Please explain why the methodology is reasonable.

(c) Please explain the advantages of the methodology compared to the previous
methodology.

(d) Does the methodology match the one used in the 2021 IRP or the one used in
the 2021 IRP Update?

Response to IPUC Data Request 10

(a) For PacifiCorp’s 2023 Integrated Resource Plan (IRP), the load and resource
balance attributes capacity to individual resources based on their availability
during two key periods. First, reliability shortfalls are most likely to occur
when loads are high and resources are limited, in particular wind and solar
resources as these are highly variable. Therefore, the majority of the capacity
value is based on resource availability during the top 5 percent net load hours,
i.e. load net of wind and solar generation, calculated separately for the
summer (June-Septe mber) and winter (October-May) seasons. Second, the top
5 percent gross load hours (not net of wind and solar) are also critical to
meeting peak demand, and resources that are available in these hours are
attributed capacity value.

Within the respective load periods, each resource’s average hourly availability
is calculated. While the top 5 percent net load hours are important, the single
hour with the lowest resource availability relative to the load requirement
including a planning reserve margin (PRM) represents the capacity achieved
by the portfolio. Since the capacity achieved in the most limiting hour is lower
than the average over the top 5 percent net load hours, an adjustment is made,
pro-rating each resource’s average availability in the top 5 percent net load
hours. A similar adjustment is made to the top 5 percent gross load hours. In
addition, the duration of energy limited resources, including batteries and
demand response (DR), is accounted for, with the duration required for
maximum contribution to peak risking through time as more energy limited
resources are added to the system.

(b) The methodology used in the 2023 IRP is a reasonable allocation of capacity
among a variety of resource types. It is generally agnostic to resource type, as
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 10

it is based on availability during key periods, with an accounting for the
characteristics of energy limited resources. That said, the methodology of
allocating capacity to individual resources is somewhat arbitrary – for
example, 1 percent or 10 percent of peak load hours could have been assessed
(or a single load hour). The total capacity achieved by the portfolio as a whole
is not impacted by this allocation among individual resources, since it is based
on the total available resources for the most restrictive hour. As a result,
changing the allocation among resources would not have a significant impact
on the capacity deficiency in a given year.

(c) The Company would note that the capacity achieved by a portfolio based on
the most restrictive hour has been present in each load and resource balance
since the 2021 IRP, therefore, the capacity deficiency would not be impacted
significantly as a result of the allocation of capacity to individual resources.
The Company has not compared the allocation of capacity to resources across
recent load and resource results.

(d) Please refer to the Company’s response to subpart (c) above.

Recordholder: Dan MacNeil

Sponsor: Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 11

IPUC Data Request 11

In terms of 3% FOT contingency reserves, Order No. 35834 required the
Company to "provide the Commission with clear evidence in its next filing that
these reserves can be reliably counted upon to provide contingency reserves."
Please explain whether and how the Company has complied with this
requirement.

Response to IPUC Data Request 11

Referencing Order No. 35834 dated June 29, 2023 issued in Case PAC-E-22-14,
the Company responds as follows:

The Company responded with regard to this issue in paragraph 6 on page 4 of its
Application in this proceeding and provided a reference to further background on
reserve requirements provided in PacifiCorp’s 2023 Integrated Resource Plan
(IRP), Volume II, Appendix F (Flexible Reserve Study).

PacifiCorp’s 2023 IRP is publicly available and can be accessed by utilizing the
following website link:

Integrated Resource Plan (pacificorp.com)

Recordholder: Dan MacNeil

Sponsor: Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 12

IPUC Data Request 12

Please explain whether all Energy Efficiency (EE), both existing EE and new EE,
in the load and resource balance is cost-effective.

Response to IPUC Data Request 12

PacifiCorp’s integrated resource planning (IRP) does not assess whether existing
energy efficiency (EE) is cost-effective, but it is reasonable to assume that
existing programs were expected to be cost-effective at the time they were
initiated. The cost-effectiveness of existing programs is provided in the
Company’s annual EE reporting. The new EE in the load and resource balance
was determined to be cost-effective as part of PacifiCorp’s 2023 IRP preferred
portfolio, though it should be noted that the IRP model identifies cost-effective
bundles that consist of many similar EE measures, and some variation within a
bundle is likely. Additional analysis is performed on individual programs and
measures before they are initiated. Note: the cost-effectiveness tests for new EE
vary by state and are reflected in the cost inputs to the IRP model.

Recordholder: Dan MacNeil / Peter Schaffer

Sponsor: Dan MacNeil / Peter Schaffer
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 13

IPUC Data Request 13

Please confirm that no early coal retirements or gas conversions are assumed in
the load and resource balance. Also, please confirm that in removing early coal
retirements, each derate adjustment was done independently in the appropriate
year in compliance with Order No. 34918.

Response to IPUC Data Request 13

Early coal retirements at Hunter Unit 1, Hunter Unit 2, Hunter Unit 3, Huntington
Unit 1 and Huntington Unit 2 were removed for the purpose of calculating the
load and resource balance. All other coal retirements reflect end of life
assumptions, environmental obligations, or, for plants where the Company has a
minority ownership share, the expected closure date identified in consultation
with the other owners.

During the extended time in service for each coal unit, the capacity was set equal
to the value during the last year of operation in PacifiCorp’s 2023 Integrated
Resource Plan (IRP) preferred portfolio, so it includes the derates specific to that
unit.

Recordholder: Dan MacNeil

Sponsor: Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 14

IPUC Data Request 14

Please explain whether the Company has made a binding commitment to join the
Western Resource Adequacy Program (WRAP). Please explain whether the
WRAP capacity is included in the load and resource balance. If so, please explain
how the amount is determined.

Response to IPUC Data Request 14

The Company has not yet made a binding commitment to join the Western
Resource Adequacy Program (WRAP) and no adjustments to the load and
resource balance have been made to account for the WRAP.

Recordholder: Dan MacNeil / Ben Faulkinberry

Sponsor: Dan MacNeil / Paul Wood
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 15

IPUC Data Request 15

Please explain why Capacity Benefit Margin is not considered in the load and
resource balance.

Response to IPUC Data Request 15

The Company assumes that “Capacity Benefit Margin” refers to North American
Electric Reliability Corporation (NERC) Standard MOD-004-1. Based on the
foregoing assumption, the Company responds as follows:

The primary transmission providers that PacifiCorp utilizes, including PacifiCorp
Transmission, the Bonneville Power Administration (BPA) and the Portland
General Electric Company (PGE), do not use capacity benefit margin (CBM) in
the assessment of available transfer capability (ATC). Because CBM is not used
by the transmission providers, it is not available to be considered in the load and
resource balance.

For additional information on PacifiCorp evaluation of CBM, please refer to the
CBM implementation document which is publicly available on PacifiCorp’s Open
Access Same-Time Information System (OASIS) website at:

https://www.oasis.oati.com/woa/docs/PPW/PPWdocs/Tab_1_-__CBMID.pdf

For additional information on BPA’s evaluation of CBM, please refer to the CBM
statement which is publicly available on BPA’s website:

https://www.bpa.gov/-/media/Aep/transmission/atc-methodology/CBMID.pdf

For additional information on PGE’s evaluation of CBM, please refer to the CBM
implementation document which is publicly available on PGE’s OASIS website
at:

https://www.oasis.oati.com/woa/docs/PGE/PGEdocs/PGE_CBMID.pdf

Recordholder: Dan MacNeil / Scott Beyer

Sponsor: Dan MacNeil / Scott Beyer
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 16

IPUC Data Request 16

Please explain whether Private Generation includes both the existing level and the
projected growth. If so, please explain how the projected growth is determined.

Response to IPUC Data Request 16

The private generation (PG) forecast includes projected growth as existing levels
of PG that are already in the actuals used to create the Company’s load forecast.
Projected growth is determined by assessing net economics from a customer
perspective over time. Economics include the acquisition and installation costs for
each technology less the impact of available incentives, and the customer’s
economic benefits of ownership such as energy and demand savings and export
credits. More detail on how projected growth is determined is provided in DNV’s
Private Generation Forecast – Behind-the-Meter Resource Assessment prepared
for PacifiCorp and dated February 2, 2023. DNV’s report is publicly available and
can be accessed by utilizing the following website link:

PacifiCorp_Private_Generation_Resource_Assessment.pdf

Recordholder: Peter Schaffer

Sponsor: Peter Schaffer

PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 17

IPUC Data Request 17

Please explain how the 13% Planning Reserve Margin is determined and why it is
reasonable for the purpose of determining the first deficit period for PURPA contracts.

Response to IPUC Data Request 17

Reliable system operation requires resources in excess of expected system load. The
additional resources are necessary for:

• Contingency reserves: compliance with North American Electric Reliability
Corporation (NERC) reliability standards requires the Company to hold
contingency reserves equal to three percent of its load plus three percent of the
generation within its balancing authority area (BAA), or approximately six percent
in total.

• Above normal load: expected system load reflects a median, or one in two year
exceedance probability. Loads will exceed this level to varying degrees in some
years.

• Above normal forced outages: forced outages of thermal and hydro resources are
largely random. While having a relatively large fleet helps smooth out variances,
when multiple units experience overlapping outages it will exceed the expected
level of forced outages and additional resources will be necessary.

• Below normal hydro conditions: hydro generation can drop across a wide area as a
result of variation in seasonal weather conditions.

PacifiCorp performed a comprehensive analysis of planning reserve margin (PRM)
based on the above factors and identified a 13 percent PRM as part of its 2019
Integrated Resource Plan (IRP). Please refer specifically to Volume II, Appendix I
(Planning Reserve Margin Study) which is publicly available and accessible by
utilizing the following website link:

Integrated Resource Plan (pacificorp.com)

The load and resource balance presented in this application reflects median load,
average forced outages, and median hydro conditions. The 13 percent PRM helps
ensure that sufficient resources will be available to cover additional needs associated
with variation in these load and resource drivers, as well as to meet contingency
reserve requirements in all hours.

Recordholder: Dan MacNeil

Sponsor: Dan MacNeil
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 18

IPUC Data Request 18

Please respond to the following questions regarding the confidential work paper
in the Application.

(a) Please explain what Tab "Smr Peak L&R (No Proxy, Update)" represents.
Specifically, what does "Update" in the Tab name mean?

(b) Please explain what Tab "Wtr Peak L&R (No Proxy, Update)" represents.
Specifically, what does "Update" in the Tab name mean?

(c) Please explain what Tab "Smr Peak L&R (No Proxy DELTA)" represents.
Specifically, how is the "DELTA" calculated?

(d) Please explain what Tab "Wtr Peak L&R (No Proxy DELTA)" represents.
Specifically, how is the "DELTA" calculated?

Response to IPUC Data Request 18

Referencing the confidential work paper accompanying the Company’s filing,
specifically confidential file “PAC-E-24-01 RMP CONF Workpapers 1-19-24”,
the Company responds as follows:

(a) “Update” refers to the Idaho-specific modifications to the load and resource
balance in PacifiCorp’s 2023 Integrated Resource Plan (IRP). It includes
information on contractual changes, plus assumptions related to early coal
retirements, qualifying facility (QF) renewal, and so on.

(b) Please refer to the Company’s response to subpart (a) above.

(c) “Delta” reflects the values from the “Update” version prepared for the Idaho
filing, as referenced in the Company’s response to subpart (a) above, minus
the values from the load and resource balance in PacifiCorp’s 2023 IRP. The
original file was provided with the Company’s confidential work papers
supporting PacifiCorp’s 2023 IRP, specifically confidential folder “Chapters,
Shortfalls - Part 1\CH6 - Load and Resource Balance”, confidential file
“CONF_Fig 6.2-6.7, Tables 6.11-6.12, 2023 IRP - L&R.xlsx”. For ease of
reference, please refer to Confidential Attachment IPUC 18 which provides a
copy of the referenced 2023 IRP confidential work paper.

(d) Please refer to the Company’s response to subpart (c) above.

Confidential information is provided subject to protection under IDAPA
31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission’s Rules of
PAC-E-24-01 / Rocky Mountain Power
March 15, 2024
IPUC Data Request 18

Procedure No. 67 – Information Exempt from Public Review, and further subject
to the non-disclosure agreement (NDA) executed in this proceeding.

Recordholder: Dan MacNeil

Sponsor: Dan MacNeil